SILVERBOW RESOURCES, INC. - FORM 8-K - EX-99 - EXHIBIT

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8-K - 8-K - SILVERBOW RESOURCES, INC.	sfy_8k-10312013.htm




COMPANY CONTACT: Paul Vincent Director – Finance & Investor Relations (281) 874-2700, (800) 777-2412	FOR IMMEDIATE RELEASE

SWIFT ENERGY ANNOUNCES:

185% INCREASE IN THIRD QUARTER 2013 EARNINGS TO $8.9 MILLION, OR $0.20 PER DILUTED SHARE;

19% INCREASE IN THIRD QUARTER 2013 REVENUES TO $153.0 MILLION;

24% INCREASE IN THIRD QUARTER 2013 CASH FLOW BEFORE WORKING CAPITAL CHANGES OF $88.5 MILLION

HOUSTON, October 31, 2013 – Swift Energy Company (NYSE: SFY) announced today earnings of $8.9 million for the third quarter of 2013, or $0.20 per diluted share, an increase of 185% when compared to third quarter 2012 earnings of $3.1 million, or $0.07 per diluted share, and an increase of 32% when compared to earnings of $6.7 million, or $0.15 per diluted share in the second quarter of 2013.

Cash flow before working capital changes (a non-GAAP measure - see page 7 for reconciliation to the GAAP measure) for the third quarter of 2013 was $88.5 million, an increase of 24% when compared to $71.2 million of the same measure in the third quarter 2012.

Production increased 6% to 3.06 million barrels of oil equivalent (“MMBoe”) during the third quarter of 2013, compared to the third quarter 2012 production of 2.87 MMBoe, and up 10% compared to second quarter 2013 production of 2.78 MMBoe.

Terry Swift, CEO of Swift Energy commented, “During the third quarter, we have continued to improve our operational efficiencies in South Texas. Despite a slower drilling and completion pace than earlier in the year, we grew production during the quarter primarily as a result of greater productivity per well. Our emphasis on drilling horizontal wells in a narrow, high quality interval of the lower Eagle Ford has resulted in more exposure to the highest quality rock available on our leases. We are also now logging each horizontal lateral we drill, resulting in more effective frac stage placement and improved performance of our completion operations. The combination of these efforts has led to significant improvement in the productivity of our wells.

“Further, we are optimizing our completion designs with longer lateral lengths, increases in frac stages and the volume of frac sand to increase initial production rates and cumulative production of Eagle Ford shale horizontal wells. We expect continued performance and efficiency improvements as we exploit these relationships in our drilling program.”

Third Quarter Revenues and Expenses

Total revenues for the third quarter of 2013 increased 19% to $153.0 million from the $128.8 million generated in the third quarter of 2012. This increase is primarily attributable to higher oil and NGL production volumes along with higher natural gas prices.

Depreciation, depletion and amortization expense (“DD&A”) of $21.90 per barrel of oil equivalent (“Boe”) in the third quarter of 2013 increased 7% from $20.52 per Boe of that measure in the comparable period in 2012 due to a higher depletable base partially offset by the addition of reserves.

Lease operating expenses, excluding transportation and processing expense and before severance and ad valorem taxes, were $7.55 per Boe in the third quarter 2013, a 3% decrease on a per unit basis compared to the same period of 2012 due to increased production volumes. Overall costs increased due to higher lease operator and compressor costs in South Texas associated with the increased production volumes, partially offset by lower salt water disposal costs.

Severance and ad valorem taxes increased to $3.83 per Boe in the third quarter 2013 from $3.72 per Boe in the third quarter of 2012.

General and administrative expenses decreased to $3.65 per Boe during the third quarter of 2013, down from $4.16 per Boe in the same period in 2012 as a result of lower overall compensation costs. Interest expense increased to $5.72 per Boe in the third quarter of 2013 compared to $4.79 per Boe for the same period in 2012 due to additional long term debt issued during the fourth quarter of 2012.

Third Quarter Pricing

The Company realized an aggregate average price of $50.72 per Boe during the quarter, an increase from the $44.51 per Boe average price received in the third quarter of 2012 and slightly higher than the $50.71 per Boe average price received in the second quarter of 2013.

In the third quarter of 2013, Swift Energy’s average crude oil prices increased 5% to $108.17 per barrel from $102.73 per barrel realized in the same period in 2012. For the same period, average natural gas prices were $3.15 per thousand cubic feet (“Mcf”), up 25% from the $2.52 per Mcf average price realized a year earlier. Prices for NGLs averaged $31.67 per barrel in the 2013 third quarter, a 1% increase from third quarter 2012 NGL prices of $31.29 per barrel.

Third Quarter Drilling Activity

In the third quarter of 2013, Swift Energy drilled twelve operated wells and participated in one non-operated well. Eleven horizontal wells were drilled to the Eagle Ford shale in the Company’s South Texas core area. This activity included eight wells in McMullen County and three wells in LaSalle County.

In the Company’s Central Louisiana core area, one non-operated well targeting the Austin Chalk was drilled in the Burr Ferry field. Also during the third quarter, one Swift operated well was drilled to the Niobrara formation in La Plata County, Colorado.

The Company currently has two operated rigs active in the Company’s South Texas core area drilling Eagle Ford shale wells and expects to add a third rig to the area during the fourth quarter.

Operations Update:

South Texas Operations

In the Company’s South Texas core area, nine operated wells were completed during the third quarter. In McMullen County, six Eagle Ford wells were completed. In LaSalle County, three Eagle Ford wells were completed.

Initial Production Test Rates of South Texas Horizontal Wells

Completed in Third Quarter 2013

(Operated unless otherwise noted)



Well Name	County/Formation Target	Oil (Bbls/d)	Natural Gas Liquids (Bbls/d)	Residual Natural Gas (MMcf/d)	Barrels of Oil Equivalent (Boe/d)	Pressure (psi)	Choke Setting
SMR EF 9H	McMullen – Eagle Ford	1,087	38	0.3	1,177	1,913	18/64”
PCQ EF 10H	McMullen – Eagle Ford	933	63	0.5	1,083	2,929	16/64”
Baetz A EF 4H	La Salle – Eagle Ford	396	300	2.4	1,101	1,750	23/64”
Carden West EF 3H	La Salle – Eagle Ford	142	330	3.6	1,076	2,454	21/64”
Hayes EF 5H	McMullen – Eagle Ford	549	69	0.6	713	2,852	15/64”
Hayes EF 6H	McMullen – Eagle Ford	682	37	0.3	769	3,050	14/64”
PCQ EF 11H	McMullen – Eagle Ford	1,030	118	1.0	1,311	2,859	20/64”
ARN EF 9H	La Salle – Eagle Ford	383	387	3.3	1,314	2,433	20/64”
Whitehurst JV EF 2H (50% W.I.)	McMullen – Eagle Ford	447	793	6.5	2,323	5,420	20/64”

The Company utilized an enhanced completion design on the Whitehurst JV EF 2H, pumping approximately 25% more proppant and fluid during stimulation operations than in prior wells. Early test results of this well are encouraging and the Company expects to utilize this enhanced completion design more frequently throughout its Eagle Ford program. During the fourth quarter, the Company also enhanced the completion technique used on the recently completed the SMR EF 11H. Frac stage intervals and perforation clusters were tightened and twice as much proppant and fluid were pumped during the completion than in previous wells in this area. Initial test rates of 1,608 Boe/d comprised of 1,446 Bbls/d of oil, 83 Bbls/d of natural gas liquids and 0.5 Mmcf/d with flowing casing pressure 2,250 psi on a 16/64” choke indicate improved performance in this well relative to prior wells completed in this area.

This technique will be utilized in future Eagle Ford completions as results continue to indicate a positive relationship between tighter frac stage intervals, higher proppant and fluid volumes and initial well performance.

Southeast Louisiana

In the Lake Washington field in Plaquemines Parish, LA, the Company continued its ongoing recompletion and production optimization program, performing 6 recompletions and 17 production optimization projects during the quarter.

Central Louisiana

In the Burr Ferry field in Vernon Parish, Louisiana, the non-operated Indigo 17-1 was completed and tested during the third quarter. Initial production rates of this well, as reported by the operator, were 617 barrels of oil per day and 4.8 million cubic feet of gas per day on a 24/64” choke with flowing tubing pressure of 5,400 psi. This well is now producing to permanent facilities and is online.

Also as previously announced, the Company has retained Scotia Waterous (USA) Inc. to conduct a sales process for its Central Louisiana assets. These assets include approximately 86,000 mineral acres and three producing oil and natural gas fields: Burr Ferry, Masters Creek and South Bearhead Creek located in the Austin Chalk and Wilcox fairways.

The audited proved reserves estimates of these fields at year end 2012 totaled 20.4 million barrels of oil equivalent, of which 65.2% were classified as oil or natural gas liquids. The Company estimates that the future resource potential of these fields is up to approximately 180 million barrels of oil equivalent.

Strategic Growth

In La Plata County, Colorado, Swift Energy drilled a well targeting the Niobrara formation during the third quarter. Completion operations are expected to be conducted during the fourth quarter of 2013.

Borrowing Base Reaffirmed

After a regularly scheduled semi-annual review by its 11 member bank group, Swift Energy’s borrowing base of $450 million was reaffirmed under its revolving credit facility effective October 28, 2013. The credit facility matures on November 1, 2017.

Price Risk Management

In the fourth quarter, Swift Energy has entered into hedging transactions covering approximately 40% of expected fourth quarter natural gas production and approximately 60% of expected fourth quarter crude oil production. The company has also entered into hedging transactions for the first quarter of 2014 covering 29,000 barrels per month of crude oil production. On an ongoing basis, details of Swift Energy’s complete price risk management activities can be found on the Company’s website (www.swiftenergy.com).

Earnings Conference Call

Swift Energy will conduct a live conference call today, October 31, at 10:00 a.m. EDT to discuss third quarter 2013 financial results and fourth quarter operational and financial expectations. To participate in this conference call, dial 973-339-3086 five to ten minutes before the scheduled

start time and indicate your intention to participate in the Swift Energy conference call. A digital replay of the call will be available later on October 31 until November 6, by dialing 855-859-2056 and using Conference ID # 72267440. Additionally, the conference call will be available over the Internet by accessing the Company’s website at www.swiftenergy.com and by clicking on the event hyperlink. This webcast will be available online and archived at the Company’s website.

About Forward Looking Statements

This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The opinions, forecasts, projections, guidance or other statements contained herein, other than statements of historical fact, are forward-looking statements, including targets for 2013 production and reserves growth, per well costs and per BOE costs, and estimates of 2013 capital expenditures and guidance estimates for the fourth quarter of 2013 and full-year 2013. These statements are based upon assumptions that are subject to change and to risks, especially the uncertainty and costs of finding, replacing, developing and acquiring reserves, availability and cost of capital, labor, services, supplies and facility capacity, hurricanes or tropical storms disrupting operations, and, volatility in oil or gas prices, uncertainty and costs of finding, replacing, developing or acquiring reserves, and disruption of operations. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Certain risks and uncertainties inherent in the Company’s business are set forth in the filings of the Company with the Securities and Exchange Commission. Estimates of future financial or operating performance provided by the Company are based on existing market conditions and engineering and geologic information available at this time. Actual financial and operating performance may be higher or lower. Future performance is dependent upon oil and gas prices, exploratory and development drilling results, engineering and geologic information and changes in market conditions.

SWIFT ENERGY COMPANY
SUMMARY FINANCIAL INFORMATION
(Unaudited)

(In Thousands Except Per Share and Price Amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013		2012		Percent Change		2013		2012		Percent Change
Revenues:
Oil & Gas Sales	$	155,049	$	127,946	21	%	$	442,418	$	396,068	12	%
Other		(2,048)		804				(714)		3,317
Total Revenue	$	153,001	$	128,750	19	%	$	441,704	$	399,385	11	%
Net Income	$	8,886	$	3,122	185	%	$	22,817	$	9,720	135	%
Basic EPS	$	0.20	$	0.07	186	%	$	0.53	$	0.23	130	%
Diluted EPS	$	0.20	$	0.07	186	%	$	0.52	$	0.23	126	%
Net Cash Provided By Operating Activities	$	76,076	$	68,005	12	%	$	225,607	$	223,684	1	%
Cash Flow Before Working Capital Changes⁽¹⁾ (non-GAAP measure)	$	88,468	$	71,215	24	%	$	233,895	$	213,041	10	%
Weighted Average Shares Outstanding (Basic)		43,389		42,901	(1)	%		43,308		42,812	(1)	%
Weighted Average Shares Outstanding (Diluted)		43,704		43,239	(1)	%		43,624		43,158	(1)	%
EBITDA (non-GAAP measure)	$	101,299	$	79,484	27	%	$	280,534	$	242,190	16	%
Production (MMBoe)		3.06		2.87	6	%		8.65		8.59	1	%
Realized Price ($/Boe)	$	50.72	$	44.51	14	%	$	51.12	$	46.10	11	%



(1)	See reconciliation on page 7. Management believes that the non-GAAP measures EBITDA and cash flow before working capital changes are useful information to investors because they are widely used by professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. Many investors use the published research of these analysts in making their investment decisions.

SWIFT ENERGY COMPANY

RECONCILIATION OF GAAP^(a) TO NON-GAAP MEASURES

(Unaudited)

(In Thousands)



	Three Months Ended
	September 30, 2013		September 30, 2012		Percent Change
CASH FLOW RECONCILIATIONS:
Net Cash Provided by Operating Activities		$76,076		$68,005	12	%
Increases and Decreases In:
Accounts Receivable	4,297		(1,884)
Accounts Payable and Accrued Liabilities	(268)		(262)
Income Taxes Payable	30		50
Accrued Interest	8,333		5,306
Cash Flow Before Working Capital Changes		$88,468		$71,215	24	%

INCOME TO EBITDA RECONCILIATIONS:
Net Income		$8,886		$3,122	185	%
Provision for Income Taxes	6,492		2,422
Interest Expense, Net	17,495		13,762
Depreciation, Depletion & Amortization & ARO (b)	68,426		60,178
EBITDA		$101,299		$79,484	27	%

	Nine Months Ended
	September 30, 2013		September 30, 2012		Percent Change
CASH FLOW RECONCILIATIONS:
Net Cash Provided by Operating Activities		$225,607		$223,684	1	%
Increases and Decreases In:
Accounts Receivable	3,696		(14,385)
Accounts Payable and Accrued Liabilities	(3,873)		3,051
Income Taxes Payable	208		248
Accrued Interest	8,257		443
Cash Flow Before Working Capital Changes		$233,895		$213,041	10	%

INCOME TO EBITDA RECONCILIATIONS:
Net Income		$22,817		$9,720	135	%
Provision for Income Taxes	15,162		6,821
Interest Expense, Net	51,297		40,546
Depreciation, Depletion & Amortization & ARO (b)	191,258		185,103
EBITDA		$280,534		$242,190	16	%



(a)	GAAP—Generally Accepted Accounting Principles
(b)	Includes accretion of asset retirement obligation

Note: Items may not total due to rounding

SWIFT ENERGY COMPANY

SUMMARY BALANCE SHEET INFORMATION

(Unaudited)

(In Thousands)



	As of September 30, 2013		As of December 31, 2012
Assets:
Current Assets:
Cash and Cash Equivalents		$97		$170
Other Current Assets	80,761		80,367
Total Current Assets	80,858		80,537

Oil and Gas Properties	5,565,107		5,151,103
Other Fixed Assets	41,993		41,690
Less-Accumulated DD&A	(3,034,614)		(2,847,773)
Total Properties	2,572,486		2,345,020

Other Assets	17,411		18,504
		$2,670,755		$2,444,061
Liabilities:
Current Liabilities		$160,767		$177,480
Long-Term Debt	1,120,402		916,934
Deferred Income Taxes	238,622		223,243
Asset Retirement Obligation	68,628		79,643
Other Long-term Liabilities	10,253		9,901
Stockholders’ Equity	1,072,083		1,036,860
		$2,670,755		$2,444,061

Note: Items may not total due to rounding

SWIFT ENERGY COMPANY

SUMMARY INCOME STATEMENT INFORMATION

(Unaudited)

In Thousands Except Per Boe Amounts



	Three Months Ended				Nine Months Ended
	September 30, 2013		Per Boe		September 30, 2013		Per Boe
Revenues:
Oil & Gas Sales		$155,049		$50.72		$442,418		$51.12
Other Revenue	(2,048)				(714)
	153,001		50.05		441,704		51.04
Costs and Expenses:
General and Administrative, net	11,146		3.65		35,062		4.05
Depreciation, Depletion & Amortization	66,948		21.90		186,526		21.55
Accretion of Asset Retirement Obligation (ARO)	1,478		0.48		4,732		0.55
Lease Operating Costs	23,078		7.55		77,459		8.95
Transportation and Processing Expense	5,783		1.89		16,678		1.93
Severance & Other Taxes	11,695		3.83		31,971		3.69
Interest Expense, Net	17,495		5.72		51,297		5.93
Total Costs & Expenses	137,623		45.02		403,725		46.65
Income Before Income Taxes	15,378		503		37,979		4.39
Provision for Income Taxes	6,492		2.12		15,162		1.75
Net Income		$8,886		$2.91		$22,817		$2.64



Additional Information:
Total Capital Expenditures	$	115,848	$	414,307
Capitalized General & Administrative	$	7,916	$	23,881
Capitalized Interest Expense	$	1,757	$	5,590
Deferred Income Tax	$	6,492	$	15,162

Note: Items may not total due to rounding

SWIFT ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOW

(Unaudited)

(In Thousands)



	Nine Months Ended
	September 30, 2013		September 30, 2012
Cash Flows From Operating Activities:
Net Income		$22,817		$9,720
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities -
Depreciation, Depletion, and Amortization	186,526		181,638
Accretion of Asset Retirement Obligation (ARO)	4,732		3,465
Deferred Income Taxes	15,162		8,239
Stock Based Compensation Expense	8,454		10,562
Other	(3,796)		(583)
Change in Assets and Liabilities -
(Increase)/Decrease in Accounts Receivable	(3,696)		14,385
Increase/(Decrease) in Accounts Payable and Accrued Liabilities	3,873		(3,051)
Decrease in Income Taxes Payable	(208)		(248)
Decrease in Accrued Interest	(8,257)		(443)
Net Cash Provided by Operating Activities	225,607		223,684

Cash Flows From Investing Activities:
Additions to Property and Equipment	(435,722)		(575,711)
Proceeds from the Sale of Property and Equipment	6,990		523
Net Cash Used in Investing Activities	(428,732)		(575,188)

Cash Flows From Financing Activities:
Net Proceeds From Bank Borrowings	203,600		102,640
Net Proceeds From Issuance of Common Stock	946		1,599
Purchase of Treasury Shares	(1,494)		(2,781)
Net Cash Provided by Financing Activities	203,052		101,458
Net Decrease in Cash and Cash Equivalents	(73)		(250,046)

Cash and Cash Equivalents at the Beginning of the Period	170		251,696
Cash and Cash Equivalents at the End of the Period		$97		$1,650

SWIFT ENERGY COMPANY

OPERATIONAL INFORMATION

QUARTERLY COMPARISON -- SEQUENTIAL & YEAR-OVER-YEAR

(Unaudited)



	Three Months Ended						Three Months Ended
	September 30, 2013		June 30, 2013		Percent Change		September 30, 2012		Percent Change
Production :
Oil & Natural Gas Equivalent (MBoe)	3,057		2,778		10	%	2,875		6	%
Natural Gas (Bcf)	8.72		7.91		10	%	8.96		(3	)%
Crude Oil (MBbl)	1,004		911		10	%	870		15	%
NGL (MBbl)	600		549		9	%	512		17	%

Average Prices:
Combined Oil & Natural Gas ($/Boe)		$50.72		$50.71	0	%		$44.51	14	%
Natural Gas ($/Mcf)		$3.15		$3.86	(18	)%		$2.52	25	%
Crude Oil ($/Bbl)		$108.17		$103.15	5	%		$102.73	5	%
NGL ($/Bbl)		$31.67		$29.74	6	%		$31.29	1	%

SWIFT ENERGY COMPANY

FOURTH QUARTER AND FULL YEAR 2013

GUIDANCE ESTIMATES



	Actual For Third Quarter 2013	Guidance For Fourth Quarter 2013					Guidance For Full Year 2013
Production Volumes (MMBoe)	3.06	3.00			-	3.10	11.65			-	11.75

Production Mix:
Natural Gas (Bcf)	8.72	8.34			-	8.61	32.6			-	32.9
Crude Oil (MMBbl)	1.00	1.01			-	1.05	3.92			-	3.95
Natural Gas Liquids (MMBbl)	0.60	0.59			-	0.61	2.30			-	2.32
Product Pricing (Note 1):
Natural Gas (per Mcf)
NYMEX Differential (Note 2)	($0.42)		($0.25	)	-	($0.50)		($0.25	)	-	($0.50)
Crude Oil (per Bbl)
NYMEX differential (Note 3)	$2.35		($5.00	)	-	---		$4.00		-	$7.00
NGL (per Bbl)
Percent of NYMEX Crude	30%	25		%	-	35%	30		%	-	35%
Oil & Gas Production Costs:
Lease Operating Costs (per Boe)	$7.55		$7.85		-	$8.05		$8.65		-	$8.75
Transportation and Processing (per Boe)	$1.89		$1.75		-	$1.85		$1.90		-	$1.95
Severance & Ad Valorem Taxes (as % of Revenue dollars)	7.6%	7.0		%	-	8.0%	7.0		%	-	8.0%
Other Costs:
G&A per Boe	$3.65		$3.80		-	$3.95		$4.00		-	$4.05
Interest Expense per Boe	$5.72		$5.70		-	$5.95		$5.85		-	$5.95
DD&A per Boe	$21.90		$21.70		-	$22.00		$21.70		-	$21.85
Supplemental Information:
Capital Expenditures (in Thousands)
Operations	$109,407		$90,693		-	$94,993		$498,000		-	$499,000
Acquisitions/(Dispositions), net	(149)	---			-	---		($6,800	)	-	($6,800)
Acquisitions/(Dispositions), Change in ARO	(3,083)	---			-	---	($14,300)			-	($14,300)
Capitalized G&A (Note 4)	$7,916		$8,000		-	$8,400		$30,000		-	$33,000
Capitalized Interest	$1,757		$2,000		-	$2,300		$8,000		-	$9,000
Total Capital Expenditures	$115,848		$100,693		-	$105,693		$515,000		-	$520,000

Basic Weighted Average Shares	43,389	43,300			-	43,500	43,300			-	43,400

Diluted Weighted Average Shares	43,704	43,600			-	43,900	43,600			-	43,800

Effective Tax Rate	42.2%	39.0		%	-	43.0%	39.0		%	-	42.0%
Deferred Tax Percentage	100%	100%					100%



Note 1:	Swift Energy maintains all its current price risk management instruments (hedge positions) on its Hedge Activity page on the Swift Energy website (www.swiftenergy.com).
Note 2:	Average of monthly closing Henry Hub NYMEX futures price for the respective contract months, included in the period, which best benchmarks the 30-day price received for natural gas sales.
Note 3:	Average of daily WTI NYMEX futures price during the calendar period reflected, which best benchmarks the daily price received for the majority of crude oil sales.
Note 4:	Does not include capitalized acquisition costs, incorporated in acquisitions when occurred.

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